AREA CLASSIFICATION AND ELECTRICAL EQUIPMENT SPACING FOR NORTH AMERICAN APPLICATION

Transcription

1 DEP SPECIFICATION AREA CLASSIFICATION AND ELECTRICAL EQUIPMENT SPACING FOR NORTH AMERICAN APPLICATION DEP Gen. DESIGN AND ENGINEERING PRACTICE DEM Shell Group of companies All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, published or transmitted, in any form or by any means, without the prior written permission of the copyright owner or Shell Global Solutions International BV.

2 Page 2 PREFACE DEP (Design and Engineering Practice) publications reflect the views, at the time of publication, of Shell Global Solutions International B.V. (Shell GSI) and, in some cases, of other Shell Companies. These views are based on the experience acquired during involvement with the design, construction, operation and maintenance of processing units and facilities. Where deemed appropriate DEPs are based on, or reference international, regional, national and industry standards. The objective is to set the recommended standard for good design and engineering practice to be applied by Shell companies in oil and gas production, oil refining, gas handling, gasification, chemical processing, or any other such facility, and thereby to help achieve maximum technical and economic benefit from standardization. The information set forth in these publications is provided to Shell companies for their consideration and decision to implement. This is of particular importance where DEPs may not cover every requirement or diversity of condition at each locality. The system of DEPs is expected to be sufficiently flexible to allow individual Operating Units to adapt the information set forth in DEPs to their own environment and requirements. When Contractors or Manufacturers/Suppliers use DEPs, they shall be solely responsible for such use, including the quality of their work and the attainment of the required design and engineering standards. In particular, for those requirements not specifically covered, the Principal will typically expect them to follow those design and engineering practices that will achieve at least the same level of integrity as reflected in the DEPs. If in doubt, the Contractor or Manufacturer/Supplier shall, without detracting from his own responsibility, consult the Principal. The right to obtain and to use DEPs is restricted, and is typically granted by Shell GSI (and in some cases by other Shell Companies) under a Service Agreement or a License Agreement. This right is granted primarily to Shell companies and other companies receiving technical advice and services from Shell GSI or another Shell Company. Consequently, three categories of users of DEPs can be distinguished: 1) Operating Units having a Service Agreement with Shell GSI or another Shell Company. The use of DEPs by these Operating Units is subject in all respects to the terms and conditions of the relevant Service Agreement. 2) Other parties who are authorised to use DEPs subject to appropriate contractual arrangements (whether as part of a Service Agreement or otherwise). 3) Contractors/subcontractors and Manufacturers/Suppliers under a contract with users referred to under 1) or 2) which requires that tenders for projects, materials supplied or - generally - work performed on behalf of the said users comply with the relevant standards. Subject to any particular terms and conditions as may be set forth in specific agreements with users, Shell GSI disclaims any liability of whatsoever nature for any damage (including injury or death) suffered by any company or person whomsoever as a result of or in connection with the use, application or implementation of any DEP, combination of DEPs or any part thereof, even if it is wholly or partly caused by negligence on the part of Shell GSI or other Shell Company. The benefit of this disclaimer shall inure in all respects to Shell GSI and/or any Shell Company, or companies affiliated to these companies, that may issue DEPs or advise or require the use of DEPs. Without prejudice to any specific terms in respect of confidentiality under relevant contractual arrangements, DEPs shall not, without the prior written consent of Shell GSI, be disclosed by users to any company or person whomsoever and the DEPs shall be used exclusively for the purpose for which they have been provided to the user. They shall be returned after use, including any copies which shall only be made by users with the express prior written consent of Shell GSI. The copyright of DEPs vests in Shell Group of companies. Users shall arrange for DEPs to be held in safe custody and Shell GSI may at any time require information satisfactory to them in order to ascertain how users implement this requirement. All administrative queries should be directed to the DEP Administrator in Shell GSI.

3 Page 3 TABLE OF CONTENTS 1. INTRODUCTION SCOPE DISTRIBUTION, INTENDED USE AND REGULATORY CONSIDERATIONS DEFINITIONS CROSS-REFERENCES SUMMARY OF MAIN CHANGES COMMENTS ON THIS DEP DUAL UNITS AREA CLASSIFICATION INTRODUCTION APPLICABILITY OF API RP 505/API RP ADMINISTRATIVE ASPECTS SUPPLEMENTAL REQUIREMENTS AND RECOMMENDED PRACTICES ELECTRICAL EQUIPMENT SPACING AND PLACEMENT INTRODUCTION LOCATION OF ELECTRICAL EQUIPMENT TANK FARMS AND DIKES CONTAINING FLAMMABLE FLUIDS BUILDINGS, SUBSTATIONS AND ELECTRICAL EQUIPMENT ROOMS OVERHEAD LINES LIGHTING NON-ELECTRICAL IGNITION SOURCES REFERENCES...21 APPENDIX A APPENDICES SAMPLE DRAWING DETAILS...23

4 Page 4 1. INTRODUCTION 1.1 SCOPE This DEP specifies requirements and gives recommendations for the determination of hazardous (classified) areas in facilities handling flammable fluids and is used in conjunction with DEP Gen. for the design of electrical installations in North America. It is based on API RP 505 and API RP 500. For the classification of areas based on IP15, refer to DEP Gen. This DEP also provides requirements and recommends practices for electrical equipment spacing and location in petroleum facilities. This DEP contains mandatory requirements to mitigate process safety risks in accordance with Design Engineering Manual DEM 1 Application of Technical Standards. This is a revision of the DEP of the same number dated January DISTRIBUTION, INTENDED USE AND REGULATORY CONSIDERATIONS Unless otherwise authorised by Shell GSI, the distribution of this DEP is confined to Shell companies and, where necessary, to Contractors and Manufacturers/Suppliers nominated by them. Any authorised access to DEPs does not for that reason constitute an authorization to any documents, data or information to which the DEPs may refer. This DEP is intended for use use for permanent and temporary installations in oil refineries, chemical plants, oils sands facilities, gas plants, exploration and production facilities as well as distribution storage depots and installations. This DEP may also be applied in other similar facilities. When DEPs are applied, a Management of Change (MOC) process should be implemented; this is of particular importance when existing facilities are to be modified. If national and/or local regulations exist in which some of the requirements could be more stringent than in this DEP, the Contractor shall determine by careful scrutiny which of the requirements are the more stringent and which combination of requirements will be acceptable with regards to the safety, environmental, economic and legal aspects. In all cases the Contractor shall inform the Principal of any deviation from the requirements of this DEP which is considered to be necessary in order to comply with national and/or local regulations. The Principal may then negotiate with the Authorities concerned, the objective being to obtain agreement to follow this DEP as closely as possible. 1.3 DEFINITIONS General definitions The Contractor is the party that carries out all or part of the design, engineering, procurement, construction, commissioning or management of a project or operation of a facility. The Principal may undertake all or part of the duties of the Contractor. The Manufacturer/Supplier is the party that manufactures or supplies equipment and services to perform the duties specified by the Contractor. The Principal is the party that initiates the project and ultimately pays for it. The Principal may also include an agent or consultant authorised to act for, and on behalf of, the Principal. The word shall indicates a requirement. The capitalised term SHALL [PS] indicates a process safety requirement. The word should indicates a recommendation.

5 Page Specific definitions Authority Having Jurisdiction (AHJ) Electrical Technical Authority Fire Area Manifold Unprotected fired equipment organization, office, or individual responsible for enforcing the local regulatory requirements. Consult with the Shell Electrical Technical Authority for the applicable AHJs for the specific installation. discipline engineer appointed by the Principal and is responsible for all technical decisions associated with the work A plant (surface) area where a sustained and intense fire is considered credible. Assembly of pipe flanges, valves, and miscellaneous fittings used to collect or distribute a common fluid or gas to or from a multiple of flowlines fired vessel that is not designed to eliminate the air intake, exhaust and hot surfaces as sources of ignition. NOTE: Protected fired equipment is normally provided with flame arresters, stack temperature shutdowns, forced draft burners with safety controls, spark arresters and insulation/cladding of external surfaces. 1.4 CROSS-REFERENCES Where cross-references to other parts of this DEP are made, the referenced section number is shown in brackets. Other documents referenced by this DEP are listed in (4). 1.5 SUMMARY OF MAIN CHANGES This DEP is a revision of the DEP of the same number dated January COMMENTS ON THIS DEP Comments on this DEP may be sent to the Administrator at standards@shell.com, using the DEP Feedback Form. The DEP Feedback Form can be found on the main page of DEPs on the Web, available through the Global Technical Standards web portal and on the main page of the DEPs DVD-ROM. 1.7 DUAL UNITS In this DEP, the International System of units (SI) shall be understood to prevail over US Customary (USC) units. USC units are provided in brackets following the SI units for information.

6 Page 6 2. AREA CLASSIFICATION 2.1 INTRODUCTION Area classification is the division of a plant or installation into hazardous (classified) areas and non-hazardous areas and the sub-division of hazardous (classified) areas into zones or divisions. This classification is based on the flammability of materials that may be present and the probability of a flammable atmosphere occurring. The classification provides a basis for the selection of electrical equipment appropriate for the defined areas and may be used as criteria for the safe positioning of other potential or continuous sources of ignition, e.g. fired heaters, internal combustion engines, etc. It can also be used as criteria in the planning and control of hot work, but should not be used as the sole criterion. Area classification refers to normal operating conditions and does not apply to catastrophic situations such as well blowouts or the rupture of process vessels. These extreme conditions require emergency measures. Area classification is an important factor in the design of electrical systems for hazardous (classified) locations. It has a major impact on safety, the cost of building and operating facilities and on the ability to maintain them. Sound engineering judgment is required for the classification of areas. Under classifying areas can lead to equipment becoming ignition sources in flammable atmospheres. Over classifying areas can lead to installations that are costly and difficult to install and maintain which can also compromise the safety of the installations. 2.2 APPLICABILITY OF API RP 505/API RP 500 Facilities that handle flammable and combustible fluids SHALL [PS] be classified in accordance with API RP 505/API RP 500, as amended and supplemented by Section 2 of this DEP. In areas where national or local codes other than API RP 505/API RP 500 apply, these codes should be reviewed and supplemented with the requirements of this DEP. For areas containing combustible dusts, refer to NFPA 499. For chemical plants refer to NFPA 497 for additional information and requirements. For additional information for classifying storage and handling areas associated with the transportation and distribution of Liquefied Petroleum Gas (LPG), refer to NFPA 58. For additional information for classifying areas involving Liquefied Natural Gas (LNG), refer to NFPA 59A. The choice between using the zone and division methods for classifying areas should include a review of the current practices at the Location and an evaluation of the economic benefits of both methods. The mixing of divisions and zones at the same site shall be avoided. Installations which were operating at the date of issue of this DEP may be evaluated against this DEP, which provides current best practice. Any proposal for modification to an existing installation shall be assessed on the basis of whether the benefits from applying the DEP outweigh the implementation costs and risks. If it is intended to reclassify an existing installation on the basis of this DEP, reclassification should cover the entire installation. This is to avoid the application of multiple area classification standards within the same installation. 2.3 ADMINISTRATIVE ASPECTS Area classification shall be undertaken only by a qualified Electrical Engineer, with sufficient background and experience to ensure that the resulting area classification accurately reflects the observed or anticipated hazardous (classified) location performance. The area classification process shall include the gathering of input from other groups and disciplines such as: Process engineering;

7 Page 7 Rotating equipment engineering; HVAC engineering; Operations and maintenance; HSSE and technical safety. Any modification to the hazardous area classification or changes to process conditions or process related equipment that may impact the area classification of an existing installation SHALL [PS] be subject to a formal change procedure and the appropriate review. Classification of locations should occur at an early stage of the project, such that equipment can be properly specified. 2.4 SUPPLEMENTAL REQUIREMENTS AND RECOMMENDED PRACTICES Extent of hazardous (classified) areas This section provides requirements and recommends practices that supplement or clarify API RP 505/API RP General The area classification boundaries should be as uniform as possible. Avoid small pockets of unclassified areas within hazardous (classified) locations and excessive fluctuations in the boundary lines. The area classification boundaries SHALL [PS] not extend beyond Shell property limits, fence lines, etc. and encroach into non-shell properties. The layout of process equipment should minimize the extent of hazardous locations classified as Group IIB (Group C) and Group IIC (Group A or B). Conduit and cable sealing requirements should be included in the determination of area classification boundaries. Boundaries may be extended to avoid the installation of additional conduit and cable seals. The following may increase the degree or extend the hazardous (classified) location boundaries: potential volume of gases or liquids that may be released as the result of an abnormal situation ; presence of highly volatile liquids such as propane, butane, propylene, etc.; for existing facilities, the past performance of the facility; and for new facilities, the observed performance of similar facilities as approved by the Electrical Technical Authority. Equipment layout, building and ventilation design, and plot plan layout shall minimize Class 1, Zone 0 or Zone 1 (Division 1) locations. The intent is to minimize the requirement for explosion-proof and intrinsically safe equipment. The maximum temperature, or T-Code, permissible SHALL [PS] be identified and based on the lowest material auto-ignition temperature present in the area. The maximum temperature may be identified per site, per unit, per building, etc. Areas containing fuel gas facilities operating at or above 345 kpa (50 psi) SHALL [PS] be classified. Odorized fuel gas facilities operating less than 345 kpa (50 psi) are normally not classified. NOTE: Municipal natural gas distribution systems normally operate at 207 kpa (30 psi) or less and are odorized with mercaptan to facilitate leak detection. API RP 505/API RP 500 Annex D considers the volatility of material and predicted release rates to determine the extent of classification boundaries. Annex D may be used to verify/validate the classification of existing facilities for low volatility and low volume releases, but should not be used to classify new grassroots facilities.

8 Page 8 Appendix A contains additional drawing details not available in API RP 505/API RP 500 that may be used for determining the extent of classified boundaries. Refer to the notes to verify the applicability of the drawing. Figure A1-1 Oil or Gas Wellhead Figure A1-2 Adequately Ventilated Process Building Figure A1-3 Inadequately Ventilated Process Building Figure A1-4 Adequately Ventilated Building Handling Produced Water or Building Subject to Similar Low-Volume Gas or Vapor Releases Figure A1-5 Manifold Figure A1-6 Air-Cooled Heat Exchanger With Open or Closed Side Louvers Figure A1-7 Control Valve Offshore production facilities For offshore production (EP) facilities, the area within 3 m (10 ft) surrounding any piping and tubing systems that contain flammable fluids (gases, vapors, liquids) and have leak sources such as valves, flanges, threads, taps, gauges and small bore appurtenances should be classified as Class I Zone 2 (Division 2) minimum. For offshore floating production (EP) facilities with drilling rigs, the entire area comprising the drill floor is classified Class I, Zone 2 (Division 2) minimum. For offshore production (EP) facilities, the interior space of turbine generator buildings and enclosures is classified Class I, Zone 2 (Division 2) regardless of ventilation and fuel gas pressure Onshore production facilities For onshore production locations, a multiplying factor should be used to account for higher operating pressures except for lower risk hydrocarbon processes as described below. Higher pressures represent larger releases and possibly increased areas where a flammable mixture may exist after such a release is realized. Engineering judgment should be used whenever addressing high-pressure hydrocarbon streams. Table 1 indicates Pressure Adjustment Factors that should be used to determine the appropriate hazard radii or distance of all dimensions shown in the appropriate figure based on equipment operating within the indicated pressure range. To apply the factors, identify the type of equipment, determine the maximum operating pressure, use the appropriate figure in API RP 505/API RP 500 for the equipment type, select the adjustment factor from Table 1, and multiply the adjustment factor times the hazard distances from the figure to establish the area classification hazard distances. For example, the area around a separator operating at kpa (ga) [1500 psig] is classified in accordance with Figure 48 (API RP 500). The hazard radii of 3 m (10 ft) illustrated in Figure 48 (API RP 500) is increased by the correction factor in Table 1, resulting in a hazardous radius of 7.5 m (25 ft). Certain applications do not represent higher release risks at higher pressures due to the reduced dispersion capacity; and therefore, the indicated pressure adjustment factors do not apply. These applications include: heavy oil production streams (14 API gravity or less); high-pressure/low volume applications (such as chemical injection systems); high water cut production streams; high hydrocarbon-carbon dioxide mixtures; or, other similar applications. The multiplying factors identified in Table 1 were derived from anticipated leak sizes and dispersion modeling methods described in IP 15. Use of adjustment factors different from

9 Page 9 those in Table 1 requires a detailed engineering analysis approved by the Electrical Technical Authority. Table 1 Pressure Adjustment Factors for Onshore Production (EP) Installations Description Typical Services Pressure Range Adjustment Factor Low Pressure LP Separation, Free Water Knock Out, Bad Oil Tank, Vapor Recovery Unit, fuel system, etc. 0 kpa to 5102 kpa (0 psig to 740 psig) (Typical ANSI 300 Class flange and below rating at 100 o F) 1.0 Medium Pressure MP (Medium Pressure) Separation, gas compression, etc kpa to 9928 kpa (741 psig to 1440 psig) (Typical ANSI 600 Class flange rating at 100 o F) 1.5 High Pressure HP Separation, manifold, Flow Line,, gas compression, dehydration, metering, export, etc. > 9928 kpa > (1440 psig) (Typical ANSI 900 Class and above flange ratings at 100 o F) Area classification documentation Area classification documentation SHALL [PS] be: kept up-to-date; and, available on site and as part of the location s permanent documentation record. Area classification documentation SHALL [PS] take into account: new or modified process equipment or process related facilities; changes in process conditions; temporary equipment installed for more than 90 days (60 days for offshore locations); and, experience in operation of the installation. Area classification drawings and supporting documentation shall be submitted to the Electrical Technical Authority for review and approval. Drawings shall be approved by Shell before purchase of electrical equipment. NOTE: Some jurisdictions mandate the approval of area classification drawings by registered professional engineers and by the local authority (AHJ) and retained by Shell. (e.g., offshore locations under MMS and US Coast Guard jurisdiction). Area classification documentation shall be in accordance with this DEP and local regulatory requirements and should include the following: drawing(s) outlining the area classification (Class, Zones or Divisions) on a plan view of the facility, including elevation views, sections, and details, as necessary, to properly show all aspects of the area classification; standards, methods and assumptions used to classify; any conditions required for the classification (use of gas detection, forced ventilation, etc.) ;

10 Page 10 for buildings and enclosed spaces, any special requirements for ventilating systems; the gas group and maximum acceptable surface operating temperature (or T-Code) of equipment for each facility, area, unit, building, etc.; and, process conditions such as operating pressures, flow rates temperatures and material present used for the classification, any other information, relative to the area classification, that is required to safely operate and maintain the facility. Area classification documentation SHALL [PS] be updated whenever process and equipment modifications that effect the area classification are made to the facility. Area classification documentation SHALL [PS] be updated, as necessary, to reflect the current facility arrangement. For onshore locations, the extent of hazardous (classified) location boundaries should be physically identified in the field. Examples of preferred methods of identification include: signs on building access points; signs on access points to fenced process areas; and, signs at access points (roads and walkways) to process areas that are not fenced or in buildings. Identification signs should include as a minimum the Class and Zone (or Division). Signs should be located at the hazardous (classified) boundary or should indicate the distance the boundary extends beyond the sign location Adequate ventilation The addition of temporary barriers, wind breaks, etc. may impact the classification of areas. If barriers or wind breaks are added to enclose the open portions of areas or enclosures that originally provided adequate ventilation in accordance with API RP 505/API RP 500, adequate ventilation must still be achieved using one of the recommended methods in API RP505/500. The preferred method of achieving adequate ventilation is by natural ventilation instead of mechanical ventilation Use of combustible gas detection The use of combustible gas detection as a method to reduce the classification of an area or building or to reduce the suitability requirements for equipment installed in an area or building requires approval by the Electrical Technical Authority. When using combustible gas detection to reduce the classification from Zone 1 (Division 1) to Zone 2 (Division 2) or from Zone 2 (Division 2) to unclassified, combustible gas detectors SHALL [PS] meet the requirements of API RP 505/API RP 500. Open path, or line of site (LOS), type combustible gas detectors SHALL [PS] not be used for this application. For unattended buildings classified as Zone 2 (Division 2) based on adequate ventilation using fugitive emissions calculations, combustible gas detection (meeting the requirements of API RP 505/API RP 500) SHALL [PS] be used to verify releases are not left undetected for long periods of time and to verify operation as a Zone 2 (Division 2) location Purged and pressurized buildings Buildings housing general-purpose electrical equipment should be located in nonhazardous (unclassified) locations. Purged and pressurized buildings require special equipment, alarming, shutdown, monitoring, permitting and maintenance. The use of purging and pressurization to reduce the classification of a building or to reduce the suitability requirements for equipment installed inside the building requires approval by the Electrical Technical Authority.

11 Page 11 Buildings that use purging and pressurization to reduce the interior area classification SHALL [PS] be designed and installed in accordance with NFPA 496 plus these additional requirements: 1. The source of air for purged and pressurized enclosures SHALL [PS] be from a non-hazardous (unclassified) location. 2. Alarms SHALL [PS] be provided at a constantly monitored location to indicate the loss of pressure for individual purged and pressurized buildings and enclosures. The use of dial-type pressure indicators or roto-meters alone without an alarm is not permitted Laboratories and analyzer shelters Refer to API RP rd edition for new requirements for classifying laboratory rooms, buildings and analyzer shelters. The new requirements in API RP rd edition SHALL [PS] be followed for Zone applications until API RP nd edition is published Fired equipment Continuous ignition sources, such as unprotected fired equipment heaters, boilers, etc., operating with fuel gas pressures less than 345kPa (50 psi) should be surrounded by a non-classified area extending 3 m (10 ft) from the surface of the heater. Fired equipment, heaters, boilers, etc. operating with fuel pressures 345 kpa (ga) [50 psig] or greater SHALL [PS] be classified Combustion engines Combustion engines operating with fuel gas pressures 345kPa (50psi) or greater SHALL [PS] be classified Ponds and ditches Area classification for ponds and ditches that may contain flammable fluids SHALL [PS] be in accordance with API RP 505/API RP 500 Figure 57 for open sumps Atmospheric vents and relief valves The recommended extent of classified locations provided in API RP 505/API RP 500 Figure 14 for atmospheric vents provide minimum distances only. The proper evaluation of vents requires review of the material properties and process conditions (e.g., pressures, flow rates, etc.) to determine the appropriate extent of the hazardous (classified) area. The recommended extent of classified locations provided in API RP 505/API RP 500 Figure 18 for atmospheric relief valves provide minimum distances only. The proper evaluation of atmospheric relief valves requires review of the material properties and process conditions (e.g., pressures, flow rates, etc.) to determine the appropriate extent of the hazardous (classified) area. Vents and relief valves connected to a common relief piping system (header) that do not release flammable gases and vapors directly to the atmosphere are normally not considered sources Combustible dusts Areas containing combustible dusts SHALL [PS] be classified in accordance with NFPA 499, Chapter 5 and the following. Petroleum Coke Handling Facilities Petroleum coke handling facilities should be classified as Class I and Class II. For facilities that can demonstrate through laboratory testing that the content of entrained volatiles is less than 8 % by volume for all feed stocks, a Class II location is not required. Sulphur Handling Facilities

12 Page 12 Outdoor locations around sulphur facilities do not normally require a hazardous classification for dust unless there is a potential for explosive dust concentrations (e.g., sulphur loading facilities). Design of sulphur-handling facilities should avoid the use of enclosed areas to minimize Class II hazardous (classified) locations.

13 Page ELECTRICAL EQUIPMENT SPACING AND PLACEMENT 3.1 INTRODUCTION This section provides requirements and recommends practices for locating electrical equipment in petroleum facilities, either within or adjacent to hazardous (classified) locations. 3.2 LOCATION OF ELECTRICAL EQUIPMENT Electrical equipment that is located in hazardous (classified) locations SHALL [PS] be approved for the location. Electrical equipment that is not approved for use in hazardous (classified) locations may become an ignition source in flammable atmospheres. The preferred order of electrical equipment placement is given below: 1) Located in non-hazardous (unclassified) location. 2) Located in an enclosure suitable for the hazardous (classified) location. 3) Located in a purged and pressurized enclosure suitable for the hazardous (classified) location. 4) Located inside an enclosure or building with gas detection suitable for the hazardous (classified) location Offshore production installations For offshore production (EP) installations, general-purpose electrical equipment shall be permitted in: The interior of air-conditioned (sealed and vapor-tight) buildings, such as quarters switchgear, MCC, office, communications, and portable buildings with no flammable vapor release sources, provided: - doorways and vent openings do not open into a hazardous (classified) location, or - the building is positively pressurized per NFPA 496, or - the interior of the building is protected by combustible gas detection per API RP 505/API RP 500. Open outdoor areas in the facility that are located at least 15m (50 ft) from any source of flammable vapor release (e.g., piping systems and tubing systems containing flammable fluids, gases, or vapors and having leak sources such as valves, flanges, threads, taps, gages, and small bore appurtenances) (Figure 1), or open outdoor areas in the facility that are located a total distance of 15 m (50 ft) measured from the source of release to the ignition source along impervious, vapor-tight barriers, such as blast walls or solid decks or roofs that will contain or deflect the flammable gas cloud and prevent it from reaching the electrical ignition sources (Figure 2). For offshore production (EP) installations, electrical equipment suitable for Zone 1/Division 1 locations SHALL [PS] be installed in: building and enclosure interiors that house hydrocarbon gas compressors; the enclosed roof space of shelters that house hydrocarbon gas compressors; and, areas within a 3 m (10 ft) radius of: - wellheads; - master valves; and, - associated choke bodies located on or adjacent to the well.

14 Page Onshore installations For onshore locations, equipment should be located to maximize the distances between ignition sources and potential sources of flammable vapor release. In addition, the direction and magnitude of prevailing winds should be considered in locating ignition sources relative to the location of potential sources of flammable vapor release. The minimum spacing requirements listed in Table 4 shall be applied for permanent and temporary electrical equipment location in relation to other process equipment. 3.3 TANK FARMS AND DIKES CONTAINING FLAMMABLE FLUIDS Electrical equipment (excluding tank instrumentation) should not be located below the level of the tank dikes, within the tank dike walls. The preferred method is to locate this equipment outside of the hazardous (classified) location. The installation of electrical equipment below the level of tank dikes requires approval by the Electrical Technical Authority. 3.4 BUILDINGS, SUBSTATIONS AND ELECTRICAL EQUIPMENT ROOMS For onshore locations handling highly volatile liquids, buildings containing only electrical equipment, such as substations and electrical equipment rooms, SHALL [PS] be located in unclassified areas and elevated at least 0.6m (2ft) above grade. Buildings adjacent to hazardous (classified) locations SHALL [PS] be vapor-tight as required in API RP 505/API RP 500 and have door and window openings directed away from process equipment, preferably on the opposite side of the hazardous (classified) area.

15 Page 15 All cable penetrations into the building will be through welded hubs or cable transit frames in order to maintain the vapor-tight integrity of the building. Electrical substations should be located upwind of the prevailing winds from cooling water towers. 3.5 OVERHEAD LINES Overhead power lines should not be installed within process units, production facilities, or product loading and distribution facilities handling flammable or combustible fluids. Clearances from un-insulated overhead power lines to process and other equipment shall be in accordance with Table 4, or local codes and regulations, whichever is greater. The basis of these distances is to minimize the impact of fallen lines on the specified equipment. Uninsulated overhead power lines up to 50kV shall have a minimum 6.4 m (21 ft) clearance (for all loading and weather conditions) over all roadways subject to truck or vehicular traffic (based on 4.15m [13.6 ft] vehicle height). Clearances shall not be temporarily reduced for special situations such as raising the elevation of the road surface. For roads with frequent crane, drilling rig or well service activity, a minimum clearance of 9.1m (30 ft) shall be provided. Additional clearance is required for vehicle heights exceeding 4.15m (13.6 ft). Refer to Table 2 for voltages greater than 50kV. Table 2 Clearances from un-insulated overhead power lines to roadways subject to truck or vehicular traffic Voltage (phase-phase, kv) Distance m(ft) 1 50 to (22) 90 to (22.6) 120 to (24) 150 to (27.6) 250 to (35.4) 300 to (51.5) Note: 1 Distances from Table 2, Alberta Electric Utility Code Distances in the Alberta Electrical Utility Code were slightly larger and were selected over those provided in Table in the National Electrical Safety Code C Overhead lines (both insulated and un-insulated) shall be routed outside of fire areas. 3.6 LIGHTING Luminaries intended for portable use in hazardous (classified) locations SHALL [PS] be approved as a complete assembly for Zone 1 (Division 1) locations. Luminaries used in confined spaces subject to exposure from flammable fluids SHALL [PS] be of a type and meet the requirements listed in Table 3 below.

16 Page 16 Table 3 Type Fixed (Permanent Installation) Temporary Installation Pneumatic Battery-Powered Requirements for Luminaries Used in Confined Spaces Requirements Approved for Zone 1 (Division 1) locations. Installed with protective glands. Supplied by armoured cable suitable for Zone 1 (Division 1) locations. Circuits exceeding 50V shall be protected by a ground fault circuit interrupter. Approved for Zone 1 (Division 1) locations. Installed with protective glands. Supplied by armoured cable (all offshore production (EP) installations) or other acceptable protection from damage and suitable for Zone 1 (Division 1) locations. Circuits exceeding 50V shall be protected by a ground fault circuit interrupter. Approved for Zone 1 (Division 1) locations. Powered by compressed air. Maximum operating voltage of 24VDC. Approved for Zone 1 (Division 1) locations. Maximum operating voltage of 12VDC. 3.7 NON-ELECTRICAL IGNITION SOURCES The location of fixed sources of ignition should be determined during facility layout planning. Fixed sources of ignition such as fired heaters and combustion engines should be located as far as practicable outside hazardous (classified) areas Flare stacks Electrical equipment, such as pilot ignition panels, SHALL [PS] be located a minimum of 10 m (30 ft) from the base of vertical flare stacks to minimize the damage associated with flare carryover. Greater clearances or heat shields may be required due to the calculated intensity of heat radiation. Heat radiation shall be limited to a maximum of 5,000 W/m 2 at electrical equipment locations. Flare stacks and flare pits SHALL [PS] not be located within 25 m (80 ft) of a hazardous location measured from the flare tip or edge of the flare pit to the hazardous (classified) location, and 10 m (30 ft) horizontal distance from the base of the flare stack to the hazardous (classified) location. These distances establish the minimum distances for hazardous (classified) locations. Other standards for plant/equipment layouts may require larger distances Fired equipment Continuous ignition sources, such as direct-fired heaters (natural or forced-draft), SHALL [PS] not be located in a hazardous (classified) area unless they are suitably protected for use in the hazardous (classified) area. Suitably protected typically includes all of the following: Flame arrester on air intake. Spark arrester on the exhaust or exhaust routed outside of the hazardous (classified) location.

17 Page 17 Fuel gas shutdowns upon loss of: - flame; - high exhaust stack temperature; and, - loss of process flow, pressure, or level Limit external hot surfaces below the ignition temperature of the material present (e.g., insulation on external surfaces) Combustion engines This section does not apply to motor vehicles Turbine engines Enclosed gas turbines with fuel systems operating above 345 kpa (ga) [50 psig] SHALL [PS] be suitable for Zone 2 (Division 2) locations. Electrical equipment associated with enclosed gas turbines with fuel systems operating above 345 kpa (ga) [50 psig] SHALL [PS] be suitable for Zone 2 (Division 2) areas. If the gas turbine enclosure is not provided with combustible gas detection, electrical equipment that is energized before the ventilation is established within the enclosure SHALL [PS] be suitable Zone 1 (Division 1) Reciprocating engines Gasoline-Fuelled engines SHALL [PS] not be used in any hazardous (classified) locations. Reciprocating engines SHALL [PS] not be located in Zone 1 (Division 1) locations for new installations. Requirements below apply to both temporary and permanent installations Diesel Engine Drivers Diesel engines SHALL [PS] not be installed in Class I Zone 0 or Zone 1 (Division 1) classified locations. For diesel engines installed and operating in Zone 2 (Division 2) hazardous (classified) locations, all of the following SHALL [PS] apply: 1. All electrical components on the skid SHALL [PS] meet Class I, Zone 2 (Division 2) requirements (devices, switches, wiring, terminal boxes, etc.). 2. Suitable physical barriers SHALL [PS] be provided on the engine skid (insulations, shields, placement, etc) to prevent potential leaks of flammable/combustible fluids from contacting the exhaust system (manifold, turbo, muffler, etc.). 3. The engine starter SHALL [PS] be either suitable for a Zone 2 (Division 2) area or nonelectrical. 4. The alternator SHALL [PS] be suitable for a Zone 2 (Division 2) area. 5. All batteries located on the engine skid SHALL [PS] be located in a battery enclosure and SHALL [PS] have no exposed energized terminals or parts. 6. The engine SHALL [PS] be provided with an automatic shutdown device that SHALL [PS] automatically shut off the air intake system for the engine when an overspeed condition is detected. This device is designed to minimize the possibility of a hydrocarbon (gas) release resulting in possible engine destruction and subsequent injury to personnel due to uncontrolled over-speed conditions. 7. The diesel engine SHALL [PS] be equipped with a spark arresting type exhaust silencer to minimize any glowing embers or sparks from being ejected from the engine exhaust system. All exhaust piping that will have a hot surface temperature SHALL [PS] be fully insulated.

18 Page The diesel engine SHALL [PS] be equipped with anti static belts and non-sparking fans to minimize the risk of ignition from a static discharge or mechanical spark Gas fuelled engine drivers (Propane/Natural Gas) Gas fuelled engines (such as natural gas, propane, etc.) SHALL [PS] not be installed in Class I Zone 0 classified locations. For Gas fuelled engines installed and operating in hazardous (classified) areas all of the following SHALL [PS] apply: 1. All electrical components on the skid SHALL [PS] be suitable for the area classification for the location in which it is installed (devices, switches, wiring, terminal boxes, etc.). 2. Suitable physical barriers SHALL [PS] be provided on the engine skid (insulations, shields, placement, etc) to prevent potential leaks of flammable/combustible fluids from contacting the exhaust system (manifold, turbo, muffler, etc). 3. The engine starter SHALL [PS] be either suitable for the required area classification or non-electrical. 4. The alternator SHALL [PS] be suitable for the required area classification of the installation location. 5. All batteries located on the engine skid (for Zone 2 [Division 2] locations only) SHALL [PS] be located in a battery enclosure and SHALL [PS] have no exposed energized terminals or parts.. Batteries SHALL [PS] not be installed in Zone 1 (Division 1) locations. 6. All engine ignition systems SHALL [PS] be equipped with a low-tension ignition system of a low fire hazard type and SHALL [PS] be designed and maintained to minimize the release of sufficient electrical energy to cause ignition of an external combustible mixture. All high-tension leads SHALL [PS] be isolated from any grounded metallic surface. All engine ignition systems installed in Zone 1 (Division 1) locations SHALL [PS] be suitable for use in that location. Ignition systems located in Zone 2 (Division 2) areas SHALL [PS] meet the requirements of ANSI/ISA SP , Chapters 5-9 and The engine SHALL [PS] be equipped with a spark arresting type exhaust silencer to minimize any glowing embers or sparks from being ejected from the engine exhaust system. All exhaust piping that will have a hot surface temperature SHALL [PS] be fully insulated. 8. The engine SHALL [PS] be provided with an automatically operated, fail safe, fuel block and bleed valve, which closes each time the engine stops. This valve should be installed on the edge of the skid and should block all fuel gas to the skid and bleed all fuel gas off of the skid down stream of the valve upon shutdown activation or loss of control power. 9. All vents from fuel gas-operated devices SHALL [PS] be vented to a safe location away from the skid or enclosure and a minimum of 5 m (15 ft) horizontally from engine exhaust. Each engine driver SHALL [PS] have a separate vent system. 10. The engine SHALL [PS] be equipped with anti static belts and non-sparking fans to minimize the risk of ignition from a static discharge or mechanical spark Vehicles Road and rail Roadways for vehicular traffic should be located outside of hazardous (classified) locations. For facilities where hazardous (classified) locations extend into roadways used for vehicular traffic, additional precautions SHALL [PS] be provided to minimize the likelihood of motor vehicles becoming a source of ignition in flammable atmospheres. Examples of additional precautions include, but are not limited to: Road access is controlled by permit, which includes the verification of the absence of flammable vapors prior to allowing access.

19 Page 19 NOTE: Specially modified vehicles are used to minimize the ignition sources and to render the vehicles suitable for the hazardous (classified) location. The use of combustible gas detectors and visible beacons placed at the hazardous (classified) location boundaries are used to alert drivers and restrict access upon detection of 40 % lower flammable (explosive) limit, LFL (LEL). Vapor-tight barriers are used to prevent heavier-than-air vapors from encroaching the roadway and to increase the effective distance from potential sources of release located near roadways. Vapor-tight barriers are used to prevent lighter-than-air vapors from encroaching the roadway where the road way passes over drains, ditches or culverts. Vehicle parking areas are sited outside of hazardous (classified) locations so vehicles can park rather than drive through the hazardous (classified) location. Normal vehicles contain many sources of ignition, including electrical circuits, hot parts on the engine, overheating brakes, and static discharges. Therefore the control of vehicle movement within hazardous (classified) locations is an important consideration in ignition control. Except for loading facilities, railways SHALL [PS] be located outside of hazardous (classified) locations.

20 Page 20 Table 4 Electrical Equipment Spacing for Onshore Oil/Gas Production and Manufacturing Facilities

21 Page REFERENCES In this DEP, reference is made to the following publications: NOTES: 1. Unless specifically designated by date, the latest edition of each publication shall be used, together with any amendments/supplements/revisions thereto. 2. The DEPs and most referenced external standards are available to Shell users on the SWW (Shell Wide Web) at SHELL STANDARDS Electrical Design North America Area Classification (Amendments to IP 15) AMERICAN STANDARDS Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2 Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2 DEP Gen DEP Gen. API RP 500 API RP 505 Issued by: American Petroleum Institute Publications and Distribution Section, 1220 L Street, North West., Washington, D.C USA General Requirements for Electrical Ignition Systems for Internal Combustion Engines in Class I, Division 2 or Zone 2, Hazardous (Classified) Locations ANSI/ISA SP Issued by: The Instrumentation, Systems and Automation Society 67 Alexander Drive P.O. Box Research Triangle Park North Carolina, Liquefied Petroleum Gas Code NFPA 58 Standard for the Production, Storage, and Handling of NFPA 59A Liquefied Natural Gas (LNG) Standard for Purged and Pressurized Enclosures for Electrical NFPA 496 Equipment Recommended Practice for the Classification of Flammable NFPA 497 Liquids, Gases, or Vapors and of Hazardous (Classified) Locations for Electrical Installations in Chemical Process Areas Recommended Practice for the Classification of Combustible Dusts and of Hazardous (Classified) Locations for Electrical Installations in Chemical Process Areas Issued by: National Fire Protection Association One Batterymarch Park PO Box 9101 Quincy, MA USA NFPA 499

22 Page 22 INTERNATIONAL STANDARDS Area Classification Code for Installations Handling Flammable Fluids, Part 15 Issued by: The Energy Institute, 61 New Cavendish Street, London W1G 7AR UK IP 15 (July 2005, 3 rd edition)

23 Page 23 APPENDIX A SAMPLE DRAWING DETAILS

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